Unrecognized extensive charge of microbial gas in the Junggar basin

Different from the Qaidam basin with about 320 billion m3 microbial gas, only limited microbial gases were found from the Junggar basin with similarly abundant type III kerogen. To determine whether microbial gases have not yet identified, natural gas samples from the Carboniferous to Cretaceous in the Junggar basin have been analyzed for chemical and stable isotope compositions. The results reveal some of the gases from the Mahu sag, Zhongguai, Luliang and Wu-Xia areas in the basin may have mixed with microbial gas leading to straight ethane to butane trends with a “dogleg” light methane in the Chung’s plot. Primary microbial gas from degradation of immature sedimentary organic matter is found to occur in the Mahu sag and secondary microbial gas from biodegradation of oils and propane occurred in the Zhongguai, Luliang and Beisantai areas where the associated oils were biodegraded to produce calcites with δ13C values from + 22.10‰ to + 22.16‰ or propane was biodegraded leading to its 13C enrichment. Microbial CH4 in the Mahu sag is most likely to have migrated up from the Lower Wuerhe Formation coal-bearing strata by the end of the Triassic, and secondary microbial gas in Zhongguai and Beisantan uplifts may have generated after the reservoirs were uplifted during the period of the Middle and Late Jurassic. This study suggests widespread distribution of microbial gas and shows the potential to find large microbial gas accumulation in the basin.

www.nature.com/scientificreports/Natural gas has been found from different tectonic units around Junggar basin, but the commercial natural gas distributes mainly in the eastern Luliang area in the east of the basin, and Hutubi, Manas, and Horgos anticlines in the southern margin of the basin.Natural gas in the NW Junggar basin is considered to have been thermally cracked from both types I and III kerogen and their derived oils 12 .The natural gas in the Mahu Sag was derived from the source rocks of the Lower Permian Fengcheng Formation with present Ro = 0.85 ~ 1.16% 13,14 .Microbial gas is reported to limit to Shazhang area in the eastern Junggar Basin 15 , based on relationships of δ 13 C 1 and δ 13 C 2 , δ 13 C 1 and C 1 /(C 2+3 ).That is, microbial gas in the Junggar basin shows limited distribution, which is much less than a proven reserve of about 320 billion m 3 in Qaidam basin with similarly abundant type III kerogen 16 .Interestingly, extremely negative δ 13 C values (− 70 to − 22‰) from high Mn calcites (average MnO = 5 wt%) have been reported from Lower Triassic Baikouquan Formation sandy conglomerates in the Mahu sag 17 , leading to a possibility for the oxidized methane to have been microbial 18,19 .In Zhongguai and Beisantai uplifts, some oils have been biodegraded, and some Fe-or Mn-rich calcite shows δ 13 C values of about + 22‰ 20 , secondary microbial gases may have occurred.Thus, it is necessary to analyze gases from Mahu sag, Zhongguai and Beisantai uplifts, and other parts of the basin to determine if they are microbial and hopefully to find new microbial gas pools in these areas and provide some clues to identifying microbial gas in the basin.

Geological setting
The Junggar Basin is one of the three major superimposed petroliferous basins in western China, which is rich in oil and gas resources, covering an area of ~ 1,34,000 km 2 , and is bounded to the northwest by the Zhayier and Halalate Mountains, to the northeast by the Kelameili and Qinggelidi Mountains, and to the south by the Yilinheibiergen and Bogeda Mountains of the Tianshan Range 21 (Fig. 1).It is an upper Paleozoic, Mesozoic, and Cenozoic superimposed basin, located at the junction of the Kazakhstan, Siberia and Tarim blocks.The basin has experienced many stages of evolution, such as the extinction and collision orogeny of the paleo Asian Ocean from the Middle Ordovician to the Early Carboniferous, the extension and fault depression from the Late Carboniferous to the early Permian, transformation of the fault depression from the middle to the Late Permian, the unification of the depression during the Mesozoic and the formation of intracontinental foreland during the Cenozoic.According to its geotectonic position, variations in basement rocks, and structural evolution, the basin can be subdivided into six structural units 22 (Fig. 1).
In the Junggar Basin, there are several sets of source rocks, including the Carboniferous, Lower Permian Jiamuhe Formation and Jurassic high-quality type III, gas-prone source rocks; and the Lower Permian Fengcheng Formation, Middle Permian Lower Wuerhe Formation high-quality oil-prone source rocks 23,24 (Fig. 2).Most of the hydrocarbon accumulation in the basin were derived from the above three suites of the source rocks in terms of the source rock distribution and hydrocarbon generation history 25 .Three major hydrocarbon-bearing systems were formed with Carboniferous and Permian oil and gas source rocks dominating in the eastern basin, Permian oil source rocks in the central and western parts, and Jurassic gas source rocks in the south.The Carboniferous source rocks are mainly tuff mudstones, with an average TOC content of 1.2%, an average hydrocarbon generation potential (PG = S 1 + S 2 ) of 0.75 mg/g.The source rock is high maturity (vitrinite reflectance Ro > 0.9%) type III kerogen and thus was favorable for natural gas generation 26 .The industrial-scale source rocks are mainly located in the Dishuiquan sag on the Luliang area.Lower Permian to Middle Permian Fengcheng Formation (P 1f ), Lower Wuerhe Formation (P 2 w), the Pingdiquan Formation (P 2 p) and the Lucaogou Formation (P 2 l) mudstones were deposited in a deep anoxic lacustrine environment and are the most important source rocks in the basin 27 .The P 1f source rocks are mostly mature to highly mature (Ro = 0.85 ~ 1.16%) lacustrine mudstones with an average TOC of 1.38% and an average S 1 + S 2 of 5.6 mg /g, and a Type I ~ II kerogen 28 .Burial history rebuilding shows that the source rocks have experienced Ro of ≤ 2% in the depression center, indicating that the source rocks are in the stage of oil to wet gas generation.This P 1f may have contributed billion-tonne oil reserves in the Mahu area 29 .
The Middle Permian source rocks show a significantly wider distribution than the P 1f and are widely distributed in the central depression of the basin and in the eastern uplift sedimentary depressions.In the northwest margin and central part of the basin, the P 2 w source rocks are mainly type III kerogen, have a TOC range from 1.4% to 1.73%, S 1 + S 2 of 2.68 mg/g, and Ro values of 0.64% ~ 1.56% 23,24 , indicating that the organic matter is within the mature to high mature stage.The P 2 l source rocks are distributed along the south margin dominated by oil shale and black-grey mudstone, with an average TOC of 7.60%, and S 1 + S 2 of 34.95 mg/g.The organic matter is mainly low to mature Type II and Type I kerogen, with Ro values ranging from 0.50% to 0.91% 25 .
Hydrocarbon production peaks and charge have been considered to occur during T 3 -J 2 , K 1 , K 2 -E and N-Q, which correspond to the tectonic development periods T 3 , J 3 , K and N-Q 28 .

Materials and methods
24 gas samples produced from Carboniferous to Cretaceous were collected (Table 1), including 6 samples from the Mahu sag, 7 samples from the Wu-Xia fault, 6 samples from the Zhongguai uplift in the western Shawan sag, 2 samples from the Luliang area and 3 samples from the Beisantai uplift (Fig. 1).The Mahu sag, Wu-Xia fault and the Zhongguai uplift are in the northwest of the Junggar basin, the Luliang area is in the central and the Beisantai uplift is in the east of the basin.All gas samples were collected from the wellhead in the commercial petroleum production field, after flushing the bottles for 15-20 min to remove air contamination.Double-ended, high-grade stainless steel bottles equipped with shut-off valves were used to collect gas samples.
The chemical composition of the gas samples has been analyzed by a combination of mass spectrometry and gas chromatography.The analysis of C 1 to C 5 hydrocarbons was carried out using an Agilent 6890 N gas chromatograph equipped with a flame ionization detector.The individual gas components of hydrocarbons were separated through a capillary column (PLOT Al 2 O 3 50 m × 0.53 mm).The GC oven temperature was initially set at 30 °C for 10 min, and then gradually increased by 10 °C/min until it reached 180 °C.After reaching this temperature, it was maintained at this level for 20-30 min.Using a Finnigan MAT-271 mass spectrometer, nonhydrocarbon gases were determined.Using the calibration curve obtained from standard gases, the concentration of each component was determined.The data of the non-hydrocarbon components obtained from the mass  www.nature.com/scientificreports/spectrometer and the data of the hydrocarbon gas component (C 1 to C 5 ) obtained from the gas chromatograph were normalized to obtain the final results of the complete component data.The stable carbon isotope ratios were measured using a Trace 1310 gas chromatograph coupled with a Thermo Finnigan Delta V Advantage mass spectrometer.The GC conditions for the carbon isotope were as follows: A HP-PLOT-Q column measuring 30m × 0.53mm × 40μm was used.The carrier gas, Helium (99.999%), flowed at a rate of 3.0 ml/min.The GC oven temperature was increased from 50 °C to 200 °C at a rate of 15 °C/min and maintained at 200 °C for 20 min.We used a split injection mode with a split ratio of 6 and an injector temperature of 200 °C.The temperature of the oxidation furnace was set at 975 °C.Carbon stable isotope ratios are expressed in δ notation in permil (‰) relative to the Vienna Pee Dee Belemnite (V-PDB) standard.
Hydrogen isotopic compositions were measured using a Thermo Delta V Advantage instrument interfaced with a Trace 1310 gas chromatograph.The GC was equipped with a 50 m × 0.53 mm HP-Al 2 O 3 /KCl column coated with a 10 μm film.The helium carrier gas flowed at a rate of 3.0 ml/min.The GC oven was held constant at 45 °C for 3 min and then heated to 200 °C at a rate of 15 °C/min and held at 200 °C for 20 min.The sample was injected using split mode with a split ratio of 6 and an injector temperature of 200 °C.The cracking furnace temperature was set to 1460 °C, and the H 3 + factor was tested at least once a day with a value of less than 10 ppm/ nA.The analyses are reported relative to the standard mean ocean water (V-SMOW) standard.

Chemical composition of the gas
All the gases analyzed are dominated by hydrocarbon gas with contents from 81.07% to 98.96% and non-hydrocarbon gas including N 2 and CO 2 with contents from 0.23% to 11.50% and 0.08 to 4.04%, respectively (Table 1).The gases from the Mahu sag have dryness coefficients (C 1 /∑C 1 − C 5 ) from 0.86 to 0.98, N 2 and CO 2 contents from 0.70% to 9.09% and 0.09 to 1.06%, respectively.The gases from the Wu-Xia fault have dryness coefficients from 0.72 to 0.94, N 2 and CO 2 contents from 0.23% to 11.50% and 0.16 to 4.04%, respectively.The gases from the Zhongguai uplift have dryness coefficients from 0.93 to 1, N 2 and CO 2 contents from 0.24% to 5.03% and 0 to 0.27%, respectively.The dryness of gas in the Luliang area and Beisantai uplift is higher, from 0.96 to 1 and 0.98 to 0.99 respectively.Among different regions of the study area, the dryness coefficients decrease from the Beisantai uplift (average 0.98) to the Luliang area (average 0.98), the Zhongguai uplift (average 0.97), the Mahu sag (average 0.91), and the Wu-Xia fault (average 0.84).

Evidence of microbial gas
The carbon isotope composition of natural gas can be used to indicate the origin, type, and maturity of the gas.δ 13 C 1 value in combination with the ratio "C 1 /(C 2 + C 3 )" of gas compositions is widely used to identify the origin of the gases (especially of methane) and the possible processes of gas generation 5,31 .The Junggar Basin gases are plotted mainly within the area of "thermogenic gases" with four samples within the microbial gas area (Fig. 3).The gases from Triassic reservoirs of the Mahu sag have C 1 /(C 2 + C 3 ) ratios from 9.06 to 66.74, and δ 13 C 1 values from − 46.8‰ to − 41.1‰, most of which are indistinguishable from other "thermogenic gases" with only the highest C 1 /(C 2 + C 3 ) ratio outside the range.A thermogenic origin for the gases is supported by the plot of the C 2 /C 3 ratio vs the differences in δ 13 C 2 − δ 13 C 3 (Fig. 4), which shows ethane and propane of the gases were derived mainly from the primary cracking of kerogen with part from oil cracking at Ro < 1.1%.However, it cannot be ruled out for some of the "thermogenic gases" to have mixed with microbial methane as indicated by methane δ 13 C 1 and δ 2 H 1 plot which shows the samples plot on the area representing an overlap between microbial gases and thermogenic gases 32 (Fig. 5).The "natural gas plot", a plot of the inverse carbon number (1/n) of the C 1 -C 4 components (the x-axis) against isotope ratio values of each component (the y-axis), showed that primary, unaltered gas, derived from a single source plot along a straight line 33 .Thus, the "natural gas plot" can be distinguished a single-source thermogenic gas from a mixed source.When we plot the data analyzed in this and previous data 30 from the Junggar Basin on the diagram, some of the gases have ethane, propane, and butane plotting along straight lines in the Mahu sag, Wu-Xia fault and Luliang area (Fig. 6).However, the methane was plotted below the lines showing significantly lighter δ 13 C values.This result suggests that the methane was not co-generated with C 2 -C 4 fraction and may have mixed with 13 C-poor methane with δ 13 C from − 54.8‰ to − 41.4‰, which is most likely to be microbial although an origin of early mature thermogenic gas cannot be ruled out 5 .
The C 2 -C 4 isotope data are extrapolated to the y-axis to predict the δ 13 C of the thermogenic methane endmember.The difference between the predicted δ 13 C of thermogenic methane and measured δ 13 C is due to microbial inputs.According to Chung's gas plot model, we can judge whether microbial or early mature gas mixed with thermogenic gas by calculating the difference between the carbon isotope value of methane in pure 2 ).CR: CO 2 reduction; F: fermentation; SM: secondary microbial; EMT: early mature thermogenic gas; OA: oil associated thermogenic gas; LMT: late mature thermogenic gas.Data are from this study, refs. 12,17,26,30) with data from this study and refs. 12,17,26,30 www.nature.com/scientificreports/thermogenic gas (δ 13 C 1, t ) and that of natural methane measured (δ 13 C 1, m ) 35 .The specific calculation methods are as follows where K is the slope of the C 2 − C 3 straight line on the natural gas plot: Besides, we find that the natural gas of Junggar Basin has a positive relationship between Δδ 13 C C1, t−C1, m and Δδ 13 C 2−1 (Fig. 7 and Supplementary Table S1), indicating that the contribution of more 13 C-depleted methane to thermogenic gases leads to increase in both the differences.This line of evidence reflects the mixing of gases with 13 C-depleted methane.
However, recent investigations show that not all the natural gases from a single source are plot along a straight line on Chung's plot, and some thermogenic gases may show dogleg distribution in C 1 to C 4 due to inhomogeneous organic matter components of source rock kerogen 2,[35][36][37][38][39] .Thus, other lines of evidence should be present to indicate that at least part of the "thermogenic gases" in Fig. 3 may have mixed with primary or secondary microbial gases.
Primary microbial gases may have occurred in the Mahu sag.CO 2 /(C 1-5 + CO 2 ) ratio from the Mahu sag T 1 b gases shows decrease with δ 13 C 1 19 .The line of evidence has been considered as the oxidation of methane to CO 2 in closed systems prior to C 2-5 charge 19 .This is because methane is the least reactive among saturated hydrocarbons 40 , and thus C 2+ alkanes are expected to be oxidized preferentially over methane and leave methane intact.On the other hand, as the result of kinetic fractionation, 12 C-rich methane is preferentially oxidized to 12 C-rich CO 2 , and when more methane is oxidized, both residual methane and newly generated CO 2 are expected to be heavier.This newly generated CO 2 may have precipitated as early calcite cement with δ 13 C values from − 31‰ to − 70‰ 18,19 .The oxidation of methane in closed systems are indicated by the positive relationship between MnO content in calcite and the δ 13 C 1 value of the associated methane 19 .Thus, it can be concluded that the pre-oxidized methane must have δ 13 C 1 heavier than that of the most 13 C-depleted Mn-bearing calcite (− 70‰) but lighter than that of the present residual methane (− 48‰).Although thermochemical oxidation of methane have been shown to have fractionation of 16-19‰ based on extrapolation of experimental results at 400-500 °C to 90-135 °C17 and a case-study on thermochemical sulfate reduction by methane 41 , microbial oxidation of methane shows a wide fractionation factor between 4 and 30 based upon aerobic culture experiments and model calculation using field data 5,42 .Thus, it is hard to determine the δ 13 C 1 value of pre-oxidized methane.The present δ 13 C CO2 values can be used to differentiate primary from secondary microbial gas, and range from − 29.4‰ to − 20.1‰ in the Mahu sag (Fig. 8).The CO 2 may be the mixtures among previously existing inorganic CO 2 , methane-derived CO 2 gas and later charged thermogenetic CO 2 along with alkanes.Considering that the calcites have more negative δ 13 C values than the associated CO 2 and a carbon isotope fractionation (1) K = δ 13 C 3 − δ 13 C 2 /(0.33 − 0.50)   www.nature.com/scientificreports/ of < 5‰ during precipitated CaCO 3 from the original gaseous CO 2 43 .The methane-derived CO 2 should have δ 13 C values lighter than the measurement values, which are much lighter than those of secondary microbial gas (> + 2‰).The three aspects of evidence, including, δ 13 C 1 values of the pre-oxidized methane from − 70‰ to − 48‰, oxidization of only methane in the Mahu sag 17 and significantly lighter CO 2 δ 13 C values than the threshold of > + 2‰ for secondary microbial gas, suggest that the early charged gas must be primary microbial gas.This is supported by the absence of biodegradation of the oils in the association with the gases 17 , one C 1 / (C 2 + C 3 ) ratio higher than the maximum value of the expected thermogenic gases and a trend showing mixing with primary microbial gases (Fig. 9).
Secondary microbial gas may have occurred in the Luliang area, Wu-Xia fault, Beisantai and Zhongguai uplifts.Oil biodegradation is indicated by strong depletion in n-alkanes, the occurrence of unresolved complex mixture (UCM), and a series of C 25 -norhopanes from the crude oil in the Permian sandstones from wells K76 in Zhongguai uplift, B47, T49 and DQ-3 in Beisantai uplift and the surrounding (Fig. 10) 20,[49][50][51] .Similar to secondary microbial gases in Australian basins 47 , propane was selectively degraded resulting in a positive shift in its δ 13 C value for some gases from Zhongguai uplift and Luliang and Wu-Xia areas as shown in Chung's plot with propane plot above the straight lines (Fig. 6b-d).Anoxic degradation of the oils and propane is expected to produce extremely 13 C-depleted methane in association with 13 C enriched CO 2 as the result of carbon isotope fractionation 49,52,53 , thus ferroan calcites from the Permian Wutonggou Formation sandstones from well B-69 in the Beisantai uplift have δ 13 C values of + 22.10‰ to + 22.16‰ 20 .

Primary microbial gas generation and accumulation in the Mahu sag
The source and charge history of the microbial gas are puzzled.Microbial methane is generally accepted to generate from type III kerogen at vitrinite reflectance Ro < 0.5%.The microbial gas may have charged earlier than thermogenic gas and oil.This proposal is supported by the following two aspects: (1) microbial gas is generated at low temperatures favorable for microorganisms to grow; (2) a calcite with δ 13 C of − 30.6‰ was precipitated at the temperature of 59 °C19 .That means that the microbial gas was charged at < 59 °C when the reservoirs were buried to < 1300m prior to the late Triassic prior to its oxidation to extremely 12 C-rich calcite based on burial and thermal history rebuilding 55 .Thus, the primary microbial gases in the Mahu sag are most likely from the P 2 w coal-bearing source rock.The source rock was deposited under sulfate-poor freshwater to brackish lacustrine environment with mudstone and shale Sr/Ba ratios from 0.36 to 0.57 56 , and are thus favorable for methanogenesis in the Lower Wuerhe Formation to generate primary microbial gas [57][58][59] , followed by its up-migration and accumulation in the overlying Lower Triassic reservoirs.The methanogenesis may have occurred prior to the late Triassic when the Lower Wuerhe Formation has organic matter maturity < 0.5% and the underlying Lower Permian Fengcheng Formation, the main source rock for the petroleum in the Mahu sag 12 experienced temperatures < 70 °C and thus no significant oil and gas has been generated 55 .

Secondary microbial gas generation in the Zhongguai and Beisantai Uplifts
From the Late Triassic to Early Jurassic, the P 1 j and P 1f source rocks in the Shawan sag reached thermal maturation stage 60 , from which oil and the associated gas generated were then migrated to structural highs and accumulated in the Zhongguai uplift.Oil and the associated gas in Triassic and Middle and Lower Jurassic reservoirs in the Beisantai uplift were generated from the Permian Pingdiquan Formation (P 2 p) in the Fukang sag during the Middle and Late Jurassic periods 20 .The oils in both Zhongguai and Beisantai uplifts were sterilized at temperatures higher than around 80-90 °C during deep burial, killing the organisms needed for oil biodegradation to occur 61 .Subsequently, the reservoirs were uplifted significantly to depths with temperatures < 80 °C during the Late Jurassic, followed by the influx of freshwater with bacteria, resulting in biodegradation of oils (Fig. 11) and thus the present oils produced and extracted from sandstones show large unrecognized complex compounds (UCM) and abundant 25-norhopanes (Fig. 10).Biodegradation of oils and propane generated 13 C-rich CO 2 and Fe-and Mn-rich calcites and 12 C-depleted methane-dominated secondary microbial gases in the areas.

Conclusions
The microbial gas can be concluded to occur from the Carboniferous to the Jurassic in Mahu sag, Zhongguai and Beisantai uplifts.The primary microbial gas in Mahu sag may have generated from the P 2 w, type III organic matter with vitrinite reflectance Ro < 0.5% prior to Late Triassic, and were partially oxidized to calcite with extremely negative carbon isotopic composition and partially mixed with later charged thermogenic gas.Secondary microbial gases from the Zhongguai and Beisantai uplifts were formed from biodegradation of oils and gases from the P 1 j and P 1f source rocks which generated abundant 25-norhopanes and 13 C-rich CO 2 precipitating as calcite.The study provides a new case showing how to identify microbial gas in a basin and has implication for microbial gas exploration in the Junggar basin.

Figure 10 .
Figure10.Biomarker chromatograms of, (a) a produced oil in the Zhongguai uplift (from ref.14 ), and (b) and (c) oils extracted from sandstone reservoir in the Beisantai uplift with data from ref.54 , showing abundant C 25 -norhopanes from biodegraded oils.

Figure 11 .
Figure 11.Schematic diagram of the oil and gas accumulation processes in the Zhongguai uplift.The location of the cross-section is shown in Fig. 1.

Table 1 .
12,15,30.Chemical composition and carbon and hydrogen isotope data of natural gas from the Junggar Basin.